This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present invention. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present invention. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
The present invention relates to a water-in-oil emulsion for use in recovering hydrocarbons from a subterranean formation. The emulsion may be used to displace hydrocarbons from the formation. The emulsions used are “basic” in the sense that they do not have added surfactants and are not solid stabilized.
Oil recovery is usually inefficient in subterranean formations (hereafter simply referred to as formations) where the mobility of the in situ oil being recovered is significantly less than that of the drive fluid used to displace the oil. Mobility of a fluid phase in a formation is defined by the ratio of the fluid's relative permeability to its viscosity. For example, when waterflooding is applied to displace very viscous heavy oil from a formation, the process is very inefficient because the oil mobility is much less than the water mobility. The water quickly channels through the formation to the producing well, bypassing most of the oil and leaving it unrecovered. Consequently, there is a need to either make the water more viscous, or use another drive fluid that will not channel through the oil. Because of the large volumes of drive fluid needed, it must be inexpensive and stable under formation flow conditions. Oil displacement is most efficient when the mobility of the drive fluid is significantly less than the mobility of the oil, so the greatest need is for a method of generating a low-mobility drive fluid in a cost-effective manner.
For modestly viscous oils—those having viscosities of approximately 10-300 centipoise (cp)—water-soluble polymers such as polyacrylamides or xanthan gum have been used to increase the viscosity of the water injected to displace oil from the formation. With this process, the polymer is dissolved in the water, increasing its viscosity. While water-soluble polymers can be used to achieve a favorable mobility waterflood for low to modestly viscous oils, usually the process cannot economically be applied to achieving a favorable mobility displacement of more viscous oils—those having viscosities of approximately 300 cp or higher. These oils are so viscous that the amount of polymer needed to achieve a favorable mobility ratio would usually be uneconomic. Further, as known to those skilled in the art, polymer dissolved in water often is adsorbed from the drive water onto surfaces of the formation rock, entrapping it and rendering it ineffective for viscosifying the water. This leads to loss of mobility control, poor oil recovery, and high polymer costs. For these reasons, use of polymer floods to recover oils in excess of about 300 cp is not usually economically feasible. Also, performance of many polymers is adversely affected by levels of dissolved ions typically found in formation brine, placing limitations on their use and/or effectiveness.
Water-in-oil macroemulsions (hereafter referred to simply as “emulsions” or “w/o emulsions”) have been proposed as a method for producing viscous drive fluids that can maintain effective mobility control while displacing moderately viscous oils. For example, the use of water-in-oil and oil-in-water macroemulsions have been evaluated as drive fluids to improve oil recovery of viscous oils. Although generally not discussed herein, microemulsions (i.e., thermodynamically stable emulsions) have also been proposed as flooding agents for hydrocarbon recovery from reservoirs, which may also be referred to as “emulsion flooding.”
While emulsions are useful for a variety of applications, they are known to be thermodynamically unstable due to their large interfacial tension between the two substances (e.g., oil and water). It is highly desirable to stabilize the emulsions for use in displacement or other applications. In almost every case, stabilization has been accomplished using an added emulsifier. See CLAESSON, PER M., et al., Surface Forces and Emulsion Stability, Encyclopedic Handbook of Emulsion Technology, CRC Press, ch. 13, p. 305 (2001). Specific emulsifier additives and techniques are discussed in the following paragraphs.
Macroemulsions used for hydrocarbon recovery have been created by addition of sodium hydroxide to acidic crude oils from Canada and Venezuela. See, e.g., H. MENDOZA, S. THOMAS, and S. M. FAROUQ ALI, “Effect of Injection Rate on Emulsion Flooding for a Canadian and a Venezuelan Crude Oil”, Petroleum Society of CIM and AOSTRA 1991 Technical Conference (Banff, Alberta), Paper 91-26; and M. FIORI and S. M. FAROUQ ALI, “Optimal emulsion design for the recovery of a Saskatchewan crude,” Journal of Canadian Petroleum Technology, 30(2), 123-132, March-April 1991. These emulsions were stabilized by soap films created by saponification of acidic hydrocarbon components in the crude oil by sodium hydroxide. The soap films reduced the oil/water interfacial tension, acting as surfactants to stabilize the water-in-oil emulsion. It is well known, therefore, that the stability of such emulsions substantially depends on the use of caustic (e.g., sodium hydroxide) for producing a soap film to reduce the oil/water interfacial tension.
Various studies on the use of caustic for producing such emulsions have demonstrated technical feasibility. However, the practical application of this process for recovering oil has been limited by the high cost of the caustic, likely adsorption of the soap films onto the formation rock leading to gradual breakdown of the emulsion, and the sensitivity of the emulsion viscosity to minor changes in water salinity and water content. For example, because most formations contain water with many dissolved solids, emulsions requiring fresh or distilled water often fail to achieve design potential because such low-salinity conditions are difficult to achieve and maintain within the actual formation. Ionic species can be dissolved from the rock and the injected fresh water can mix with higher-salinity resident water, causing breakdown of the low-tension stabilized emulsion.
Bragg et al., (U.S. Pat. Nos. 5,855,243, 5,910,467, 5,927,404, 6,068,054) describe using a high water-cut water-in-oil emulsion stabilized with microparticles and diluted with dissolved gas to displace viscous oils from subterranean formations. As stated in '243, these so-called “solid stabilized emulsions” are such that “solid particles are the primary means, but not necessarily the only means, by which the films surrounding the internal phase droplets of an emulsion are maintained in a stable state under formation conditions for a sufficient time to use an emulsion as intended (e.g., enhance rate and/or amount of hydrocarbon production from a formation).”
Binder et al., (U.S. Pat. No. 3,149,669) describes generating emulsions and injecting the emulsions into a subterranean oil reservoir to displace the oil and improve recovery. The patent however teaches that addition of an emulsifier is preferred (see Col 3, lines 54-71; and the example given in Col 4, lines 43-51). In particular, '669 states (Col 3, 54-57): “An emulsifier is preferably used to stabilize the emulsion. The emulsifier will normally comprise between about 0.1 and about 4% of the weight of the emulsion.” The present invention differs from the '669 patent in that the present invention identifies a method of selecting a hydrocarbon fluid with enumerated properties such that additives are not needed. Use of emulsifiers add cost and complexity to emulsion generation and injection into oil reservoirs and thus the present invention improves upon the '669 invention.
R. Varadaraj (U.S. Pat. No. 7,338,924) describes a method to utilize stable oil-in-water-in-oil (O/W/O) emulsions to displace oil from subterranean reservoirs. The '924 patent teaches adding an organic salt to the emulsion as the recommended approach. No method is taught or suggested for creating such stable emulsions without addition of a stabilizing agent.
The method of using a water-in-oil emulsion can be highly effective for certain oils and formations. The use of microparticles, typically clays or silica fines, however can be problematic in certain cases. In particular, for lower permeability formations the fines may lead to pore plugging, especially near the wellbore, and ultimately injectivity reduction. Additionally, the logistics of supplying microparticles to remote locations may lead to substantial costs. Thus there is a need to reduce or remove the presence of microparticles in certain emulsions.
Accordingly, there is a need for a method to produce an emulsion that can be made economically and is capable of performing under a wide range of formation conditions, including salinity, temperature, and permeability.
Other relevant information may be found in U.S. Pat. No. 3,811,501; U.S. Pat. No. 4,136,738; U.S. Pat. No. 4,299,286; U.S. Pat. No. 4,418,753; U.S. Pat. No. 4,478,280; U.S. Pat. No. 5,065,821 U.S. Pat. No. 5,104,516; U.S. Pat. No. 5,322,617; U.S. Pat. No. 5,607,016; and U.S. Provisional Patent Application No. 61/070,133 titled “Enhancing Emulsion Stability,” filed on Mar. 20, 2008.